The present invention relates to a method of treating a gaseous mixture comprising hydrogen (H2), carbon dioxide (CO2) and at least one combustible gas selected from the group consisting of hydrogen sulfide (H2S), carbon monoxide (CO) and methane (CH4). The invention is preferably integrated with fossil fuel-fired power stations to reduce or eliminate emission of CO2 and other atmospheric pollutants. The main fuel of interest is coal although the invention has application in the generation of power from other fuels such as bitumen, petcoke and natural gas.
There is an need to develop improved methods for efficient power generation from fossil fuels, including carbonaceous and hydrocarbonaceous fuels, and biomass fuel, with virtually zero emission of atmospheric pollutants, particularly CO2. There are three basic techniques in the context of CO2 capture from power generation equipment using these types of fuel:
(a) pre-combustion decarbonization;
(b) CO2 removal from flue gases following combustion; and
(c) oxy-fuel combustion systems.
The present invention is in the field of pre-combustion decarbonization. In pre-combustion decarbonization, the fuel is reacted with pure oxygen (O2) and converted by a partial oxidation reaction into a synthesis gas mixture consisting predominantly of H2 and CO. The CO can be converted to H2 and CO2 by a catalytic shift conversion reaction with water (H2O). The CO2 and H2 are separated and the H2 is burned in a gas turbine combined cycle power generation system producing electric power. The sulphur content of the fuel, present as H2S following the shift conversion step, must be separated from the CO2 for disposal and not vented to atmosphere either as H2S or SO2. Thus, CO2 and H2S must be separated from the H2 prior to combustion. The CO2 is usually compressed to pipeline pressure (about 100 bar to about 250 bar) for transfer to a storage site.
Previous studies have typically shown that pre-combustion decarbonization can be applied to power generation from coal with CO2 capture leading to power generation efficiencies of about 36% to 40% based on the lower heating value (“LHV”) of the fuel.
H2 gas may be produced from carbonaceous or hydrocarbonaceous fuels (such as petcoke, bitumen, natural gas and, in particular, coal) using partial oxidation technology to initially convert the fuel, by reaction with O2 at high temperature, to a crude synthesis gas mixture comprising H2, CO, CO2, H2O, H2S, carbonyl sulfide (COS), carbon disulfide (CS2), CH4 and other minor impurities.
The crude synthesis gas is usually cooled and, particularly when gasifying coal, any ash removed therefrom. The cooling and ash removal steps may be carried out simultaneously by washing the gas with water. Alternatively, the gas can be cooled in a heat exchanger and the heat recovered to produce, for example, high pressure steam. The bulk of the ash is, in this case, removed in a molten state from the gasifier and the remaining fly ash is removed by filtration following heat recovery. Either way, the resultant cooled gas is then usually passed through a sulfur-tolerant shift catalyst (possibly in a multi-stage system with inter-stage cooling or with a single stage reactor with internal cooling) to convert CO with steam to H2 and CO2. Any COS and CS2 is converted simultaneously to H2S and CO2.
Current technology would then be used to selectively separate H2S and CO2 from H2, usually by passing the gas into a physical solvent absorption process which are expensive and require significant utility consumption during operation.
The Inventors have discovered that non-selective separation of H2S and CO2 from H2 provides advantages over existing selective separation technologies, particularly when the process is integrated with a gas turbine for the production of electricity.
EP-A-0262894 (Lerner et al; published 6 Apr. 1988) discloses a process for co-production of enriched streams of separate CO2 and H2 products from, for example, the effluent from a steam methane reformer. A pressure swing absorption (“PSA”) unit is used for the separation producing a primary stream of enriched hydrogen which may be liquefied. The purge stream from the H2 PSA, comprising CO2 and combustible gases including CO, CH4 and H2, is combusted to yield CO2 and to produce electricity which can be used, for example, in the liquefaction of the H2. The H2 PSA purge is combusted in the presence of pure or enriched oxygen in an internal combustion engine, gas turbine or other combustion device that can be used to generate power. The exhaust gas from the combustor is typically cooled, condensing the water vapor which is subsequently removed and, preferably, a portion of the exhaust gas is recycled as feed to the combustor to control the maximum temperature achieved in the combustor. It is further disclosed that waste heat recovery from the combustion exhaust may be used to raise steam. EP-A-0262894 exemplifies the use of an internal combustion engine to combust the PSA purge gas.
It is an objective of preferred embodiments of the present invention to provide an improved, lower cost high efficiency method of separating synthesis gases derived from partial oxidation or reforming of carbonaceous or hydrocarbonaceous fuels or biomass into pure H2 and pure CO2 gases and, in some embodiments, a separate stream containing any sulfur from the primary fuel.
An integrated gasification combined cycle (“IGCC”) system may be used to generate power, such as electrical power, from a carbonaceous fuel such as coal. The fuel is gasified to produce a synthesis gas mixture of CO and H2 which is converted in a catalytic shift reaction, in the presence of H2O, to produce H2 and CO2. Any sulfur present in the fuel is converted to H2S plus minor amounts of COS and CS2. After separation from CO2 and, if present, H2S, H2 is used as a fuel in a gas turbine to generate power. It is known in the art to recover heat from gas turbine exhaust to preheat boiler feed water for an oxyfuel boiler in a coal fired power station.
It is a further objective of preferred embodiments of the present invention to improve the efficiency of not only an oxyfuel fired boiler but also an IGCC system such that, when integrated together in a combined system, the overall efficiency of the combined system is improved by providing further heat integration between the component parts of the combined system.
A conventional oxy-fuel combustion system uses a recycle of hot flue gas, typically at a temperature of 300° C. to 350° C. In addition, the quantity of net flue gas produced is reduced compared to a conventional power station boiler due to the absence of nitrogen and argon in the boiler system except for air in-leakage and any nitrogen/argon in the oxygen feed. Both these effects reduce the quantity of low grade heat available for condensate heating prior to de-aeration and boiler feed water heating following condensate pumping to steam delivery pressure. It has been proposed to use adiabatic compression for the oxygen plant air compressors and for the CO2 compressor to allow the hot compressed air and CO2 to transfer heat to the condensate and boiler feed water (“Oxy-Combustion Processes For CO2 Capture From Advanced Super-Critical PF and NGCC Power Plants”, Dillon et al; Proceeding on the 7th International Conference on Greenhouse Gas Control Technologies; September 2004; Vancouver, Canada). This still leaves a deficit which must be made up by using intermediate pressure steam bled from the steam power cycle or some other means.
It is an object of preferred embodiments of the invention to provide an additional means of boiler feed water and condensate preheat by combining the coal gasification and oxy-fuel combustion systems.
One of the most widely used methods of coal gasification is a method in which partially oxidised coal is quenched from a temperature of over 1400° C. down to a temperature of, typically, 240° C. to 270° C. by direct contact with water. The gas is quenched in a section at the bottom of the gasifier and this, not only cools the gas, but washes away the bulk of the ash from the coal. The gas is then scrubbed to clean and further cool it. Preheated water can be used to increase the water content of the quenched gas which can be in the range 60-80% by volume at a typical operating pressure of 60 bar. The high content of water, with maximum preheat of the quench water, favours the shift conversion of CO and water vapour to CO2 and H2 with maximum conversion and minimum temperature rise.
It is an object of preferred embodiments of this invention to use a gasifier at its maximum possible pressure with coal and with quench water preheated to a maximum temperature typically within 20° C. of its boiling point preferably to ensure the best conversion of CO to H2 in the shift reactor with minimum temperature rise.
It is an object of preferred embodiments of the present invention to increase the power recovery from the pressure letdown system by maximising the quench water pre-heat and the operating pressure.
The maximisation of the heating of the quench water gives a maximum quantity of steam present with the H2 rich product gas from the shift conversion. This combines with the maximisation of the pressure in the system allows a maximisation in the power produced in a pressure let-down turbine which follows the shift conversion. The gas pressure is reduced to a value which, allowing for pressure loss in the downstream system, gives a suitable pressure for the H2 rich gas to be used as fuel in a gas turbine following CO2 and H2S removal. The use of a power turbine following CO shift allows the heat released in the exothermic CO shift reaction to be converted to power at very high efficiency.
It is a further object of preferred embodiments of the invention to allow the use of a simple low cost proven coal gasification system with water quench integrated with an oxy-fuel boiler so that the steam content of the synthesis gas is efficiently used to preheat boiler feed water and condensate from the oxy-fuel boiler and also to heat the quench water, which is recycled condensate from the cooled H2 plus CO2 stream.